Amplify Energy (AMPY) 10-Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from               to               

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

Delaware	45-3691816
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
4400 Post Oak Parkway, Suite 1900
Houston, Texas	77027
(Address of principal executive offices)	(Zip Code)

(713) 595-9400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The number of shares outstanding of our common stock at May 2, 2013 is shown below:

Class	Number of shares outstanding
Common stock, $0.01 par value	68,376,508

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2013

TABLE OF CONTENTS

	Page
Glossary of Oil and Natural Gas Terms	3
PART I - FINANCIAL INFORMATION
Item 1.- Financial Statements
Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012 (unaudited)	5
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012 (unaudited)	6
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2013 (unaudited)	7
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012 (unaudited)	8
Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2. - Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. - Quantitative and Qualitative Disclosures About Market Risk	36
Item 4. - Controls and Procedures	37
PART II - OTHER INFORMATION
Item 1. - Legal Proceedings	38
Item 1A. - Risk Factors	38
Item 2. - Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3. - Defaults Upon Senior Securities	39
Item 4. - Mine Safety Disclosures	39
Item 5. - Other Information	40
Item 6. - Exhibits	40
SIGNATURES	41
EXHIBIT INDEX	42

2

GLOSSARY OF OIL AND NATURAL GAS TERMS

Bbl:  One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

Boe:  Barrel of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d:  Barrels of oil equivalent per day.

Completion:  The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Dry hole:  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production do not exceed production expenses and taxes.

Exploratory well:  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.

MMBoe:  One million barrels of oil equivalent.

Net acres:  The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

NYMEX:  The New York Mercantile Exchange.

Proved reserves:  Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reasonable certainty:  A high degree of confidence.

Recompletion:  The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves:  Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

3

Reservoir:  A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spud or Spudding:  The commencement of drilling operations of a new well.

Wellbore:  The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

Working interest:  The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

4

PART I - FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	50,625		$	18,878
Accounts receivable:
Oil and gas sales	44,620			35,618
Joint interest billing	15,070			10,815
Other	2,407			3,866
Commodity derivative contracts	1,935			5,695
Deferred income taxes	11,517			6,027
Other current assets	9,109			8,573
Total current assets	135,283			89,472
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	1,968,902			1,836,664
Other property and equipment	5,601			5,038
Less accumulated depreciation, depletion, and amortization	(316,270		)	(274,294		)
Net property and equipment	1,658,233			1,567,408
OTHER ASSETS:
Commodity derivative contracts	1,171			1,717
Other noncurrent assets	24,797			25,413
Total other assets	25,968			27,130
TOTAL	$	1,819,484		$	1,684,010
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	6,206		$	29,196
Accrued liabilities	149,368			98,649
Commodity derivative contracts	13,244			7,582
Total current liabilities	168,818			135,427
LONG-TERM LIABILITIES:
Asset retirement obligations	15,706			15,245
Commodity derivative contracts	9,095			3,943
Long-term debt	796,450			694,000
Deferred income taxes	191,142			190,625
Other long-term liabilities	1,148			1,189
Total long-term liabilities	1,013,541			905,002
COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding	—			—
Series A mandatorily convertible preferred stock, $0.01 par value, $1,040 and $1,000 liquidation value, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding	3			3
Common stock, $0.01 par value, 300,000,000 shares authorized; 68,363,508 and 66,619,711 shares issued and outstanding, respectively	683			666
Additional paid-in-capital	831,479			830,003
Retained deficit/accumulated loss	(195,040		)	(187,091		)
Total stockholders’ equity	637,125			643,581
TOTAL	$	1,819,484		$	1,684,010

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	For the Three Months Ended March 31,
	2013			2012
REVENUES:
Oil sales	$	72,218		$	45,082
Natural gas sales	8,795			3,450
Natural gas liquid sales	9,719			6,272
Losses on commodity derivative contracts — net	(20,124		)	(24,665		)
Other	414			105
Total revenues	71,022			30,244
EXPENSES:
Lease operating and workover	13,871			6,467
Severance and other taxes	5,955			5,376
Asset retirement accretion	254			134
Depreciation, depletion, and amortization	41,976			28,027
General and administrative	11,026			6,064
Total expenses	73,082			46,068
OPERATING LOSS	(2,060		)	(15,824		)
OTHER INCOME (EXPENSE)
Interest income	5			7
Interest expense — net of amounts capitalized	(10,867		)	(1,690		)
Total other income (expense)	(10,862		)	(1,683		)
LOSS BEFORE TAXES	(12,922		)	(17,507		)
Income tax benefit	4,973			—
NET LOSS	$	(7,949	)	$	(17,507	)
Preferred stock dividend (see Note 8)	(4,117		)	—
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(12,066	)	$	(17,507	)
Basic and diluted net loss per share attributable to common shareholders	$	(0.18	)	N/A
Weighted average number of common shares outstanding	65,634			N/A

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(See Note 9 for Share History)

(In thousands, except share amounts)

	Preferred  Stock		Common Stock		Additional Paid-in-Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’  Equity
Balance as of December 31, 2012	$	3	$	666	$	830,003	$	(187,091	)	$	643,581
Share-based compensation	—		17		$	1,476	$	—		1,493
Net loss	—		—		—		(7,949		)	(7,949		)
Balance as of March 31, 2013	$	3	$	683	$	831,479	$	(195,040	)	$	637,125

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(7,949	)	$	(17,507	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Unrealized losses on commodity derivative contracts, net	15,120			18,166
Asset retirement accretion	254			134
Depreciation, depletion, and amortization	41,976			28,027
Share-based compensation	1,244			—
Deferred income taxes	(4,973		)	—
Accrued interest on mandatorily redeemable convertible preferred units	—			762
Amortization of deferred financing costs	984			216
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	(9,002		)	2,877
Accounts receivable — JIB and other	(2,796		)	2,747
Other current assets	(536		)	(2,413		)
Accounts payable	(925		)	161
Accrued liabilities	28,847			1,186
Other	(41		)	(40		)
Net cash provided by operating activities	$	62,203		$	34,316
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(132,538		)	(72,466		)
Net cash used in investing activities	$	(132,538	)	$	(72,466	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	102,450			—
Proceeds from issuance of mandatorily redeemable convertible preferred units	—			40,000
Deferred financing costs	(368		)	—
Net cash provided by financing activities	$	102,082		$	40,000
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	31,747			1,850
Cash and cash equivalents, beginning of period	18,878			7,344
Cash and cash equivalents, end of period	$	50,625		$	9,194
SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued — not paid	$	82,562		$	82,845
Cash paid for interest, net of capitalized interest of $7.1 million and $0.7 million, respectively	—			1,106

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc., through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas and natural gas liquids. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), which was previously a wholly owned subsidiary of Midstates Petroleum Holdings LLC (“Holdings LLC”). Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.’s initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates Petroleum Company LLC became a wholly owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. The terms “the Company,” “we,” “us,” “our,” and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise. The term “Holdings LLC” refers solely to Midstates Petroleum Holdings LLC prior to the corporate reorganization.

On October 1, 2012, the Company closed on the acquisition of all of Eagle Energy Production, LLC’s producing properties as well as their developed and undeveloped acreage primarily in the Mississippian Lime liquids play in Oklahoma and Kansas for $325 million in cash and 325,000 shares of the Company’s newly designated Series A Preferred Stock with an initial liquidation preference value of $1,000 per share (the “Eagle Property Acquisition”). The Company funded the cash portion of the Eagle Property Acquisition purchase price with a portion of the net proceeds from the private placement (which also closed on October 1, 2012) of $600 million in aggregate principal amount of 10.75% senior unsecured notes due October 1, 2020. Subsequent to the closing of the Eagle Property Acquisition, the Company has oil and gas operations or properties in Louisiana, Oklahoma and Kansas.

At March 31, 2013, the Company operated oil and natural gas properties as one reportable segment: the exploration, development and production of oil, natural gas and natural gas liquids. The Company’s management evaluated performance based on one reportable segment as there were not significantly different economic or operational environments within its oil and natural gas properties.

2. Summary of Significant Accounting Policies

Basis of Presentation

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2012 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 21, 2013.

All intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year’s consolidated financial statements and related footnotes to conform them to the current year presentation. In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2013, and determined that none would have a material impact on the Company’s condensed consolidated financial statements.

9

3. Fair Value Measurements of Financial Instruments

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy:

·Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

·Level 2 — Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are commodity derivative contracts with fair values based on inputs from actively quoted markets. The Company uses a discounted cash flow approach to estimate the fair values of its commodity derivative contracts, utilizing commodity futures price strips for the underlying commodities provided by a reputable third-party.

·Level 3 — Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments — Commodity derivative contracts reflected in the condensed consolidated balance sheets are recorded at estimated fair value. At March 31, 2013 and December 31, 2012, all of the Company’s commodity derivative contracts were with six and five bank counterparties, respectively, and are classified as Level 2.

Derivative instruments listed below are presented gross and include collars, swaps, and put options that are carried at fair value. The Company records the net change in the fair value of these positions in “Losses on commodity derivative contracts — net” in the Company’s unaudited condensed consolidated statements of operations. See Note 4 for additional information on the Company’s derivative instruments and balance sheet presentation.

10

	Fair Value Measurements at March 31, 2013
	Quoted Prices in Active  Markets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	11,975	$	—	$	11,975
Commodity derivative NGL swaps			2,272		—		2,272
Commodity derivative oil collars	—		220		—		220
Commodity derivative gas collars			943		—		943
Commodity derivative differential swaps	—		1,766		—		1,766
Total assets	—		17,176		—		17,176
Liabilities:
Commodity derivative oil swaps	$	—	$	26,597	$	—	$	26,597
Commodity derivative NGL swaps			141		—		141
Commodity derivative oil collars	—		376		—		376
Commodity derivative gas collars			430				430
Commodity derivative differential swaps	—		8,865		—		8,865
Total liabilities	$	—	$	36,409	$	—	$	36,409

	Fair Value Measurements at December 31, 2012
	Quoted Prices in Active  Markets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	16,133	$	—	$	16,133
Commodity derivative NGL swaps			2,353		—		2,353
Commodity derivative oil collars	—		428		—		428
Commodity derivative gas collars			2,026		—		2,026
Commodity derivative differential swaps	—		2,661		—		2,661
Total assets	—		23,601		—		23,601
Liabilities:
Commodity derivative oil swaps	$	—	$	15,091	$	—	$	15,091
Commodity derivative NGL swaps			458		—		458
Commodity derivative oil collars	—		287		—		287
Commodity derivative gas collars			185				185
Commodity derivative differential swaps	—		11,693		—		11,693
Total liabilities	$	—	$	27,714	$	—	$	27,714

11

4. Risk Management and Derivative Instruments

The Company is exposed to fluctuations in crude oil, NGL and natural gas prices on its production. The Company believes it is prudent to manage the variability in cash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil, NGL and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps, collars and options, to reduce fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGL and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its crude oil, NGL and natural gas production.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at March 31, 2013 would have been approximately $3.1 million.

Commodity Derivative Contracts

As of March 31, 2013, the Company had the following open commodity derivative contract positions:

	Hedged Volume	Weighted-Average Fixed  Price
Oil (Bbls):
WTI Swaps — 2013	1,827,674				$	95.16
WTI Swaps — 2014	2,425,950				$	88.98
WTI Swaps — 2015	1,460,000				$	86.69
WTI Collars — 2013	152,253	$	85.27	-	$	100.70
WTI Collars — 2014	164,400	$	88.49	-	$	97.94
WTI to LLS Basis Differential Swaps — 2013 (1)	1,182,764				$	5.83
WTI to LLS Basis Differential Swaps — 2014 (1)	501,000				$	5.35
Natural Gas (Mmbtu):
Collars — 2013	1,674,747	$	3.68	-	$	4.91
Collars — 2014	1,685,004	$	3.99	-	$	5.09
NGL (Bbls):
NGL Swaps — 2013	193,500				$	63.42
NGL Swaps — 2014	151,500				$	62.16

(1)The Company enters into swap arrangements intended to capture the positive differential between the Louisiana Light Sweet (“LLS”) pricing and West Texas Intermediate (“NYMEX WTI”) pricing.

Balance Sheet Presentation

The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s condensed consolidated balance sheets at March 31, 2013 and December 31, 2012, respectively (in thousands):

12

Type	Balance Sheet Location (1)	March 31, 2013			December 31, 2012
Oil Swaps	Derivative financial instruments — Current Assets	$	11,888		$	16,004
Oil Swaps	Derivative financial instruments — Non-Current Assets	87			129
Oil Swaps	Derivative financial instruments — Current Liabilities	(18,305		)	(11,485		)
Oil Swaps	Derivative financial instruments — Non-Current Liabilities	(8,292		)	(3,606		)
NGL Swaps	Derivative financial instruments — Current Assets	1,729			1,624
NGL Swaps	Derivative financial instruments — Non-Current Assets	543			729
NGL Swaps	Derivative financial instruments — Current Liabilities	(134		)	(336		)
NGL Swaps	Derivative financial instruments — Non-Current Liabilities	(7		)	(122		)
Oil Collars	Derivative financial instruments — Current Assets	80			221
Oil Collars	Derivative financial instruments — Non-Current Assets	140			207
Oil Collars	Derivative financial instruments — Current Liabilities	(347		)	(238		)
Oil Collars	Derivative financial instruments — Non-Current Liabilities	(29		)	(49		)
Gas Collars	Derivative financial instruments — Current Assets	430			1,129
Gas Collars	Derivative financial instruments — Non-Current Assets	513			897
Gas Collars	Derivative financial instruments — Current Liabilities	(353		)	(112		)
Gas Collars	Derivative financial instruments — Non-Current Liabilities	(77		)	(73		)
Basis Differential Swaps	Derivative financial instruments — Current Assets	1,766			2,625
Basis Differential Swaps	Derivative financial instruments — Non-Current Assets	—			36
Basis Differential Swaps	Derivative financial instruments — Current Liabilities	(8,063		)	(11,319		)
Basis Differential Swaps	Derivative financial instruments — Non-Current Liabilities	(802		)	(374		)
Total		$	(19,233	)	$	(4,113	)

(1)The fair value of derivative instruments reported in the Company’s condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all derivative instruments in the unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets as of March 31, 2013 and December 31, 2012, respectively (in thousands):

		March 31, 2013
Not Designated as ASC 815 Hedges:	Balance Sheet Classification	Gross Recognized Assets/ Liabilities		Gross Amounts Offset		Net Recognized Fair Value Assets/ Liabilities
Derivative assets:
Commodity contracts	Derivative financial instruments - current	$	15,893	$	13,958	$	1,935
Commodity contracts	Derivative financial instruments - noncurrent	1,283		112		1,171
		$	17,176	$	14,070	$	3,106
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	27,202	$	13,958	$	13,244
Commodity contracts	Derivative financial instruments - noncurrent	9,207		112		9,095
		$	36,409	$	14,070	$	22,339
		December 31, 2012
Not Designated as ASC 815 Hedges:	Balance Sheet Classification	Gross Recognized  Assets/  Liabilities		Gross Amounts Offset		Net Recognized Fair Value Assets/ Liabilities
Derivative assets:
Commodity contracts	Derivative financial instruments - current	$	21,603	$	15,908	$	5,695
Commodity contracts	Derivative financial instruments - noncurrent	1,998		281		1,717
		$	23,601		16,189	$	7,412
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	23,490	$	15,908	$	7,582
Commodity contracts	Derivative financial instruments - noncurrent	4,224		281		3,943
		$	27,714	$	16,189	$	11,525

Losses on Commodity Derivative Contracts

The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in “Losses on commodity derivative contracts — net”, within revenues in the condensed consolidated statements of operations.

The following table presents realized net losses and unrealized net losses recorded by the Company related to the change in fair value of the derivative instruments in “Losses on commodity derivative contracts — net” for the periods presented (in thousands):

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	For the Three Months Ended March 31,
	2013			2012
Realized net losses	$	(5,004	)	$	(6,499	)
Unrealized net losses	(15,120		)	(18,166		)

5. Property and Equipment

	March 31, 2013			December 31, 2012
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	1,667,293		$	1,522,723
Unevaluated properties	301,609			313,941
Other property and equipment	5,601			5,038
Less accumulated depreciation, depletion, and amortization	(316,270		)	(274,294		)
Net property and equipment	$	1,658,233		$	1,567,408

Oil and Gas Properties

The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. For the three months ended March 31, 2013, the Company capitalized $1.5 million of internal costs to oil and gas properties.  Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold that results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income.

Depreciation, depletion and amortization is calculated using the Units of Production Method (“UOP”).  The UOP calculation, multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value.  For the three months ended March 31, 2013 and 2012, depletion expense related to oil and gas properties was $41.6 million and $27.9 million, respectively, and $28.51 and $37.10 per Boe, respectively.

Unevaluated Property

Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least quarterly to determine if impairment has occurred. Unevaluated property was $301.6 million at March 31, 2013 compared to $313.9 million at December 31, 2012, decreasing primarily due to continued development of the Company’s evaluated acreage.

Other Property and Equipment

Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets, which range from five to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

Ceiling Test

The Company performs a ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net

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revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations (“ARO”) accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations.

At March 31, 2013 and 2012, capitalized costs did not exceed the ceiling, and no impairment to oil and gas properties was required.

Eagle Property Acquisition—October 2012

On October 1, 2012, the Company closed on the Eagle Property Acquisition. The assets acquired include certain interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments.  The Company’s results from operations include the results from the properties acquired in the Eagle Property Acquisition beginning October 1, 2012.

The following table presents unaudited pro forma information for the Company as if the Eagle Property Acquisition occurred on January 1, 2012:

	For the Three Months Ended March 31, 2012
Revenues and other	$	52,889
Net income (loss)	(14,134		)
Preferred stock dividends	6,500
Income (loss) attributable to common shareholders	$	(20,634	)
Net loss per common share - basic	N/A
Net loss per common share - diluted	N/A

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Eagle Property Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company’s consolidated results of operations actually would have been had the acquisition been completed on January 1, 2012. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined company. The unaudited pro forma consolidated results reflect the following pro forma adjustments:

·Adjustment to recognize incremental DD&A expense, using the UOP method, resulting from the purchase of the properties;

·Adjustment to recognize additional general and administrative expense as a result of the purchase of the properties;

·Adjustment to recognize the issuance of $600 million in aggregate principal amount of 10.75% senior unsecured notes due 2020, associated deferred financing cost amortization, and interest expense, net of amounts capitalized;

·Adjustment to recognize asset retirement obligation accretion on properties acquired;

·Adjustment to recognize a pro forma income tax provision;

·                �� Adjustment to recognize dividends associated with the issuance of 325,000 shares of Series A Preferred Stock; and

·Elimination of transaction costs incurred in 2012 that are directly related to the transaction and do not have a continuing impact on the combined company’s operating results.

6. Asset Retirement Obligations

AROs represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the ARO at inception is capitalized as part of the carrying amount of the related long-lived assets. AROs approximated $15.7 million and $15.2 million as of March 31, 2013 and December 31, 2012, respectively.

The liability has been accreted to its present value as of March 31, 2013 and December 31, 2012. The Company evaluated its wells and determined a range of abandonment dates through 2058.

The following table reflects the changes in the Company’s AROs for the three months ended March 31, 2013 (in thousands):

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Asset retirement obligations at January 1, 2013	$	15,245
Liabilities incurred	207
Revisions	—
Liabilities settled	—
Current period accretion expense	254
Asset retirement obligations at March 31, 2013	$	15,706

7. Long-Term Debt

The Company’s long-term debt as of March 31, 2013 and December 31, 2012 is as follows (in thousands):

	March 31, 2013		December 31, 2012
Revolving credit facility, due 2017	$	196,450	$	94,000
Senior notes, due 2020	600,000		600,000
Less: current maturities of debt	—		—
Long-term debt	$	796,450	$	694,000

Reserve-based Credit Facility

As of March 31, 2013, the Company’s credit facility consisted of a $500 million senior revolving credit facility (the “Credit Facility”) with a borrowing base of $285 million, as recently redetermined in March 2013, when the borrowing base was increased from $250 million.

Borrowings under the Credit Facility are secured by substantially all of the Company’s oil and natural gas properties and currently bear interest at LIBOR plus an applicable margin between 1.75% and 2.75% per annum. At March 31, 2013 and March 31, 2012, the weighted average interest rate was 2.4% and 3.1%, respectively.

In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

The borrowing base under the Credit Facility is subject to semiannual redeterminations in March and September and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent, acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations. The next scheduled borrowing base redetermination date is September 2013.

Under the terms of the Credit Facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

The Credit Facility contains financial covenants, which, among other things, set a maximum ratio of debt to earnings before interest, income tax, depletion, depreciation, and amortization (EBITDA) of not more than 4.0 to 1, a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, but not limited to, restrictions on the Company’s ability to make any dividends, distributions or redemptions.

As of March 31, 2013, the Company was in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. The Company’s current ratio at March 31, 2013 was 1.4 to 1.0. At March 31, 2013, the Company’s ratio of debt to EBITDA was 3.48.

The Company believes the carrying amount of the Credit Facility at March 31, 2013 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate.

Senior Notes

On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the “Senior Notes”) in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The proceeds from the offering of $582 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the cash portion of, and expenses related to, the Eagle Property Acquisition, to

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pay the expenses related to the amendments to the Company’s revolving credit facility, to repay $182.9 million in outstanding borrowings under the Company’s Credit Facility, and for general corporate purposes.

The Senior Notes were co-issued on a joint and several basis by Midstates Petroleum Company, Inc. and its wholly owned subsidiary, Midstates Petroleum Company LLC. Midstates Petroleum Company, Inc. does not have any operations or independent assets other than its 100% ownership interest in Midstates Petroleum Company LLC and there are no other subsidiaries of the Company. The Senior Notes indenture does not create any restricted assets within Midstates Petroleum Company LLC, nor does it impose any significant restrictions on the ability of Midstates Petroleum Company LLC to pay dividends or make loans to Midstates Petroleum Company, Inc. or limit the ability of Midstates Petroleum Company, Inc. to advance loans to Midstates Petroleum Company LLC.

At any time prior to October 1, 2015, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, the Company may redeem all or a part of the Senior Notes at a redemption price equal to 100% of the principal amount of Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, up to, the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, on the Senior Notes redeemed, up to, the redemption date.

The Indenture contains covenants that, among other things, restrict the Company’s ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) consolidate, merge or sell substantially all of the Company’s assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts and (x) enter into agreements restricting the ability of the Company’s subsidiaries to pay dividends.

Upon the occurrence of certain change of control events, as defined in the Indenture, each holder of the Senior Notes will have the right to require that the Company repurchase all or a portion of such holder’s Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase. In connection with the private placement of the Senior Notes, on October 1, 2012, the Company entered into a Registration Rights Agreement (the “Notes Registration Rights Agreement”) obligating the Company to use reasonable best efforts to file an exchange registration statement with the Securities and Exchange Commission (the “Commission”) so that holders of the Senior Notes can offer to exchange the Senior Notes for registered notes having substantially the same terms as the Senior Notes and evidencing the same indebtedness as the Senior Notes. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the Senior Notes. If the Issuers fail to satisfy these obligations on a timely basis, the annual interest borne by the Senior Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

The estimated fair value of the Notes was $657.0 million as of March 31, 2013 (Level 1 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective annual interest rate for the Senior Notes was approximately 11.1% for the three months ended March 31, 2013.

8. Equity and Share-Based Compensation

Common and Preferred Shares

On April 24, 2012, in connection with the Company’s initial public offering, a corporate reorganization occurred and each common unit of Holdings LLC was converted into approximately 185.5 common shares of the Company and as a result, the Company issued 47,634,353 shares of its common stock to the unitholders of Holdings LLC.

On April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer and sale of 27,600,000 shares of $0.01 par value common stock, which included

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6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments.

After the corporate reorganization and the completion of its initial public offering discussed above, the Company is authorized to issue up to a total of 300,000,000 shares of its common stock with a par value of $0.01 per share, and 50,000,000 shares of its preferred stock with a par value of $0.01 per share. Holders of the Company’s common shares are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and to receive ratably in proportion to the shares of common stock held by them any dividends declared from time to time by the board of directors. The common shares have no preferences or rights of conversion, exchange, pre-exemption or other subscription rights.

With respect to preferred shares, the Company is authorized, without further stockholder approval, to establish and issue from time to time one or more classes or series of preferred stock with such powers, preferences, rights, qualifications, limitations and restrictions as determined by its board of directors.

Series A Preferred Stock

In connection with the Eagle Property Acquisition, on September 28, 2012, the Company filed a Certificate of Designations with the Secretary of State of the State of Delaware to designate 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the “Series A Preferred Stock”). On October 1, the Company issued 325,000 shares of Series A Preferred Stock in connection with the closing of the Eagle Property Acquisition. The shares of Series A Preferred Stock have an initial liquidation value of $1,000 per share. The Series A Preferred Stock are convertible into shares of the Company’s common stock on or after October 1, 2013. At such time, the Series A Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number of shares of the Company’s common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. If not previously converted, the Series A Preferred Stock will be subject to mandatory conversion into shares of the Company’s common stock on September 30, 2015 at a conversion price based upon the volume weighted average price of the Company’s common stock during the 15 trading days immediately prior to the mandatory conversion date, but in no instance will the price be greater than $13.50 per share (or 24.1 million common shares, before any increase in liquidation preference) or less than $11.00 per share (or 29.5 million common shares, before any increase in liquidation preference). Dividends on the Series A Preferred Stock will accrue at a rate of 8.0% per annum, payable semiannually on March 30 and September 30, at the Company’s sole option, in cash or through an increase in the liquidation preference. Additionally, the Series A Preferred Stock will be entitled to participate on an as converted basis in any common stock dividends declared during the period in which Series A Preferred Stock is outstanding.

Holders of the Series A Preferred Stock are entitled to vote on an as converted basis on all matters submitted to common shareholders for approval other than the election of members to the Company’s board of directors and proposals seeking the approval of certain transactions where the holders of the Series A Preferred Stock would be entitled to consideration at least equal to their liquidation preference.  After October 1, 2013, in the event the Company’s volume weighted share price exceeds the conversion price then in effect for 15 consecutive trading days, rights to vote the Series A Preferred Stock on an as converted basis will terminate. Additionally, as long as any shares of Series A Preferred Stock remain outstanding, holders of the Series A Preferred Stock are entitled to elect one member to the Company’s board of directors.

On March 30, 2013, the Company elected to pay the $13 million dividend due on that date through an increase in the Series A Preferred Stock liquidation preference to $1,040.  As a result, the Company will be obligated to issue between 962,963 and 1,181,818 additional shares of common stock upon conversion of the Series A Preferred Stock, with the ultimate number of shares dependent upon the conversion price then in effect or, if conversion were to occur at the mandatory conversion date, the Company’s average share price during the 15 days preceding such mandatory conversion date, subject to the limits described above.

For the three months ended March 31, 2013, the $4.1 million Series A Preferred Stock dividend (paid through the adjustment to the liquidation preference discussed above) is based upon the estimated fair value of 481,481 common shares that would have been issued had the Series A Preferred Stock dividend for the three months been converted into common shares using a conversion price of $13.50 per share.

The issuance of the Series A Preferred Stock to Eagle pursuant to the Eagle Purchase Agreement was approved by the Company’s stockholders holding a majority of the outstanding shares of the Company’s common stock.

The following table summarizes changes in the number of outstanding shares since December 31, 2012:

	Number of Shares
	Preferred Stock	Common Stock
Balance as of December 31, 2012	325,000	66,619,711
Grants of restricted stock	—	1,746,066
Forfeitures of restricted stock	—	(2,269	)
Balance as of March 31, 2013	325,000	68,363,508

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Incentive Units.

At March 31, 2013, 1,623 incentive units were issued and outstanding. These incentive units were issued prior to the Company’s initial public offering. In connection with the corporate reorganization that occurred immediately prior to our initial public offering, these incentive units held in the Company were contributed to FR Midstates Interholding, LP (“FRMI”) in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI’s aggregate capital contributions and investment expenses (“FRMI Profits”). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.

Share-based Compensation, Post-Initial Public Offering

2012 Long Term Incentive Plan.

On April 20, 2012, the Company established the 2012 Long Term Incentive Plan (the “2012 LTIP”) and filed a Form S-8 with the SEC, registering 6,563,435 shares of common stock for future issuance under the terms of the 2012 LTIP. The 2012 LTIP provides a means for the Company to attract and retain employees, directors and consultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stock ownership or awards, the value of which is tied to the performance of the Company, thereby strengthening their concern for the welfare of the Company and their desire to remain employed.

The 2012 LTIP provides for the granting of Options (Incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the “Awards”). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. A total of 6,563,435 common share Awards are authorized for issuance under the 2012 LTIP and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

Non-vested Stock Awards.

Subsequent to the completion of the Company’s initial public offering and pursuant to the 2012 LTIP, through March 31, 2013 the Company had 2,729,155 nonvested shares of restricted common stock to directors, management and employees outstanding. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant); however, shares granted under the LTIP to directors on or after April 1, 2013 are subject to one-year cliff vesting.

The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.

The following table summarizes the Company’s non-vested share award activity for the three months ended March 31, 2013:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2012	985,358		$	12.61
Granted	1,746,066		$	7.54
Vested	—		$	—
Forfeited	(2,269	)	$	9.40
Non-vested shares outstanding at March 31, 2013	2,729,155		$	9.37

Unrecognized expense as of March 31, 2013 for all outstanding restricted stock awards was $21.4 million and will be recognized over a weighted average period of 2.58 years.

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At March 31, 2013, 3,834,280 shares remain available for issuance under the terms of the 2012 LTIP.

The following table summarizes share-based compensation costs (after amounts capitalized to oil and gas properties) recognized as expense by the Company for the periods presented (in thousands):

	For the Three Months Ended March 31,
	2013		2012
Incentive units	$	—	$	—
2012 LTIP restricted shares	1,244		—
Total share-based compensation expense	$	1,244	$	—

For the three months ended March 31, 2013, the Company capitalized $0.2 million of qualifying share-based compensation costs to oil and gas properties.

9. Income Taxes

Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company’s equity holders were responsible for income tax on the Company’s profits. In connection with the closing of the Company’s initial public offering, the Company merged into a corporation and became subject to federal and state income taxes.

Consistent with the applicable guidance, the Company revises its estimate of its annual income tax rate each quarter, and reflects this change in estimate on year-to-date activity in each quarter.  For the quarter ended March 31, 2013, the Company estimated its effective annual tax rate for 2013 to be approximately 39%. This revision is primarily attributable to a change in expected pre-tax income for the 2012 fiscal year resulting from unrealized losses attributable to hedging activity. The Company’s estimated effective tax rate for 2013 differs from the federal statutory rate of 35% due to state income taxes. The Company expects to incur a tax loss in the current year (due principally to the ability to expense certain intangible drilling and development costs under current law) and thus no current income taxes are anticipated to be paid. This tax loss is expected to result in a net operating loss carryforward at year-end; however, no valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize all tax attributes.  This future taxable income arises from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax bases.  Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed.

As of March 31, 2013, the Company has not recorded a reserve for any uncertain tax positions.

10. Earnings (Loss) Per Share

The Company’s Series A Preferred Stock issued in connection with the Eagle Property Acquisition has the nonforfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. The Company’s nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted earnings (loss) per share, pursuant to the two-class method. In the calculation of basic earnings (loss) per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net income

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per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented.

The following table is a calculation of the basic and diluted net loss for the three months ended March 31, 2013. For the 2012 comparable period, the calculation is not applicable as the Company was not a public company until April 25, 2012.

	For the Three Months Ended March 31, 2013 (1)
Numerator
Net loss	$	(7,949	)
Less:
Preferred stock dividend	(4,117		)
Undistributed earnings to participating securities	—
Net loss attributable to common shareholders — basic and diluted	$	(12,066	)
Denominator
Weighted average basic and diluted common shares outstanding (2)	65,634
Basic and diluted loss per common share	$	(0.18	)

(1)For the 2012 comparable period, the calculation is not applicable as the Company was not a public company until April 25, 2012.

(2)At March 31, 2013, there were no other dilutive securities outstanding to consider for the period presented as the nonvested restricted stock grants and Series A Preferred Stock had already been considered as part of the two-class method.

The aggregate number of common shares outstanding at March 31, 2013 was 68,363,508, 2,729,155 of which were unvested restricted shares. The aggregate number of shares of Series A Preferred Stock outstanding at March 31, 2013 was 325,000, representing on an as-converted basis approximately 25.1 million common shares based upon a conversion price of $13.50 per share, which have been excluded from the computation of net loss per share.

11. Commitments and Contingencies

Litigation

Clovelly Oil Company.

The Company is a defendant in an action brought by Clovelly Oil Company (the “Plaintiff” or “Clovelly”) in the 13th Judicial District Court in Louisiana in May 2009. The Plaintiff alleges that the Company is subject to an unrecorded Joint Operating Agreement (“JOA”) dated July 16, 1972, as a result of the Company’s 2007 purchase of a 43.75% working interest in certain acreage. The Plaintiff further alleges that the Company is bound by the 1972 JOA and that the Plaintiff is entitled to 56.25% of the Company’s 242.28-acre Crowell Land & Mineral lease. The Company was not a signatory to the JOA, and believes that it is protected by the Louisiana Public Records Doctrine, which generally provides that instruments involving real property are without effect as to third parties unless the instrument is filed of record in the appropriate mortgage or conveyance records of the parish in which such property is located.

The Company made a motion for summary judgment on all of the Plaintiff’s claims, and the 13th Judicial District Court granted that motion on August 14, 2009. The Plaintiff appealed the district court’s decision to the Third Circuit Court of Appeal, and on April 7, 2010, the Third Circuit Court of Appeal reversed and remanded the case to the district court for trial. On August 9, 2010, the Plaintiff amended its original petition to add Wells Fargo Bank, N. A., which holds a mortgage on the acreage, as a defendant.

On September 27, 2011, the district court granted the Company’s motion for partial summary judgment declaring that the JOA does not apply to any new leases acquired after July 16, 1972 which are not extension or renewal leases. The district court also granted a motion for summary judgment filed by Wells Fargo asserting that, as a mortgage holder of a mortgage covering the applicable lease, Wells Fargo is protected by the Public Records Doctrine. The Plaintiff again appealed.

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On June 6, 2012, the Third Circuit Court of Appeal reversed the district court’s partial summary judgment decision that the JOA does not apply to any new leases. It held that, if the Company is subject to the JOA, then the JOA applies to leases acquired by the Company after the 2007 purchase that are within the acreage covered by the JOA. Separately, the Third Circuit Court of Appeal upheld the district’s court decision that Wells Fargo is protected by the Public Records Doctrine. The Third Circuit Court of Appeal then remanded the case to the district court for a determination of whether the Company had assumed the obligations under the JOA.

On December 14, 2012 the Louisiana Supreme Court granted the Company’s petition seeking a review and reversal of the Third Circuit Court of Appeal’s September 2012 decision in the Company’s ongoing litigation with Clovelly Oil. On March 19, 2013, the Louisiana Supreme Court held that the JOA does not apply to new leases acquired by the Company after the time the JOA was executed on July 16, 1972 and unanimously reversed the Third Circuit Court of Appeals decision and reinstated the 13th Judicial District Court’s ruling where it granted the Company’s motion for partial summary judgment. On May 3, 2013, the Louisiana Supreme Court denied Clovelly’s Application for Rehearing. The Company intends to seek dismissal of Clovelly’s claims with the 13th Judicial District Court, as the Supreme Court’s ruling held for the Company on the central matter at issue in the action. This dismissal would eliminate any exposure to the Company from this lawsuit, as all leases at issue in the matter were acquired after July 16, 1972.

Other.

We are involved in other disputes or legal actions arising in the ordinary course of our business. We may not be able to predict the timing or outcome of these or future claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effect on our financial condition, results of operations or cash flows. Currently, we are not party to any legal proceedings that, individually or in the aggregate, are reasonably expected to have a material adverse effect on our financial position, results of operations, or cash flows.

12. Subsequent Events

Anadarko Basin Acquisition

On April 3, 2013, the Company entered into a Purchase and Sale Agreement (the “Agreement”) with Panther Energy Company, LLC, Red Willow Mid-Continent, LLC and Linn Energy Holdings, LLC (collectively, the “Sellers”), pursuant to which the Company agreed to acquire producing properties as well as undeveloped acreage in the Anadarko Basin in Texas and Oklahoma (the “Transaction”). The aggregate purchase price, subject to adjustment as provided in the Agreement, consists of $620 million in cash. In connection with the Agreement, the Company has agreed to pay a termination fee in the amount of $62 million in the event it materially breaches the Agreement.

The Company and the Sellers have made customary representations, warranties and covenants in the Agreement. The Sellers have made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Agreement and the closing of the Transaction and not to engage in certain kinds of transactions during that period, subject to certain exceptions.

Consummation of the Transaction is subject to various conditions, including, among others, (1) the accuracy of the representations and warranties of the parties as of the closing date, including the absence of any material adverse effect with respect to the Sellers’ business, (2) the release of certain liens in connection with the repayment of the Sellers’ indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions. The transaction will be effective April 1, 2013 and closing is expected to occur on or about May 31, 2013. The Agreement may be terminated under customary circumstances.

The purchase will be accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the Company is required to allocate the purchase price to tangible and identifiable intangible assets acquired and liabilities assumed based on their fair values at the closing date. The excess of the purchase price over those fair values, if any, is recorded as goodwill. Disclosures required by ASC 805, Business Combinations, will be provided once the closing occurs and the initial accounting for the acquisition is complete.

Commitment for Bridge Credit Facility and Amendment to Revolver

In connection with the execution of the Agreement, on April 3, 2013, the Company entered into a commitment letter with Morgan Stanley Senior Funding, Inc., SunTrust Bank and SunTrust Robinson Humphrey, Inc. to, among other things, (1)

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provide for an unsecured bridge credit facility in the amount of up to $620 million and (2) provide a commitment to amend, amend and restate, or refinance and replace the existing secured revolving credit facility (the “Amended Revolving Credit Facility”) to increase the borrowing base to $425 million and to accommodate, among other things, the issuance, incurrence and/or compliance with the terms of the bridge loans and other debt securities that may be issued or loans that may be incurred in lieu of, or in connection with the replacement of, the bridge loans, including senior unsecured notes. The availability of loans under the bridge credit facility and the effectiveness of the Amended Revolving Credit Facility are subject to the consummation of the Transaction and other customary conditions. The proceeds of the bridge credit facility may be used solely to fund the Transaction, to pay transaction costs and expenses in connection therewith or repay outstanding debt under the existing secured revolving credit facility. If entered into, the bridge credit facility will initially bear interest at LIBOR, subject to a 1.50% floor, plus either 7.50% or 8.00% (based on the indicative rating(s) received in respect of the bridge facility or senior unsecured notes) and thereafter such margin is subject to increases. The bridge credit facility matures on the first anniversary of the closing date of the Transaction and contains customary terms regarding the conversion of the bridge loans into other debt instruments subject to certain caps on yield, the highest of which is set at 11.50%. The obligations under the bridge credit facility would be guaranteed by the same entities that guarantee the existing Credit Facility.

If entered into, the Amended Revolving Credit Facility would mature on the fifth anniversary of the entrance into the Amended Revolving Credit Facility and the aggregate amount available under the facility would increase to $425 million, subject to reduction in the event that the amount of assets acquired in connection with the Transaction is less than expected. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, by $650 million, thereby permitting the incurrence of the bridge loans or the issuance of other debt without causing a $0.25 reduction in the borrowing base for every $1 of such debt incurred or issued.

The definitive loan documentation for the bridge loan facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to those in other similar transactions and will otherwise be similar to the terms set forth in the existing Credit Facility. The definitive loan documentation for the Amended Revolving Credit Facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to the terms set forth in the existing Credit Facility and which address the above mentioned accommodations and allowances.

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Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2012, and the related management’s discussion and analysis contained in our annual report on Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 21, 2013, as well as the unaudited condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. In particular, the factors discussed in this report on Form 10-Q and detailed in our annual report filed on Form 10-K dated and filed with the SEC on March 21, 2013, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

·business strategy;

·estimated future net reserves and present value thereof;

·technology;

·cash flows and liquidity;

·financial strategy, budget, projections and operating results;

·oil and natural gas realized prices;

·timing and amount of future production of oil and natural gas;

·availability of drilling and production equipment;

·availability of oilfield labor;

·the amount, nature and timing of capital expenditures, including future development costs;

·availability and terms of capital;

·drilling of wells, including our identified drilling locations;

·successful results from our identified drilling locations;

·marketing of oil and natural gas;

·the closing and financing of the Transaction (as defined in “—Anadarko Basin Acquisition”);

·the integration and benefits of the Eagle Property Acquisition and the Transaction or the effects of the acquisitions on our cash position and levels of indebtedness;

·infrastructure for salt water disposal;

·property acquisitions;

·costs of developing our properties and conducting other operations;

·general economic conditions;

·effectiveness of our risk management activities;

·environmental liabilities;

·counterparty credit risk;

·the outcome of pending and future litigation;

·governmental regulation and taxation of the oil and natural gas industry;

·developments in oil-producing and natural gas-producing countries;

·uncertainty regarding our future operating results; and

·plans, objectives, expectations and intentions contained in this annual report that are not historical.

All forward-looking statements speak only as of the date of this quarterly report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or

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the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Overview

We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources in the Upper Gulf Coast Tertiary trend onshore in Louisiana, which we refer to as our “Gulf Coast” operating area. We began operations in the Mississippian Lime trend in Oklahoma and Kansas, which we refer to as our “Mid-Continent” operating area, with the October 1, 2012 closing of our acquisition (“Eagle Property Acquisition”) of interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments from Eagle Energy Production, LLC (“Eagle Energy”).

We were incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of our initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for our newly issued common shares, and as a result, Midstates Petroleum Company LLC became our wholly-owned subsidiary and Midstates Petroleum Holdings LLC ceased to exist as a separate entity.

With the completion of our initial public offering, we became a publicly traded company. Our common stock is listed on the NYSE under the ticker symbol “MPO.” The terms “the Company,” “we,” “us,” “our,” and similar terms, when used in the present tense, prospectively or for historical periods since April 25, 2012 refer to us and our subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital resources in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity, constraints, inventory storage levels, basis differentials, and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Anadarko Basin Acquisition

On April 3, 2013, we entered into a Purchase and Sale Agreement (the “Agreement”) with Panther Energy Company, LLC, Red Willow Mid-Continent, LLC and Linn Energy Holdings, LLC (collectively, the “Sellers”), pursuant to which we agreed to acquire producing properties as well as undeveloped acreage in the Anadarko Basin in Texas and Oklahoma (the “Transaction”). The aggregate purchase price, subject to adjustment as provided in the Agreement, consists of $620 million in cash. In connection with the Agreement, we agreed to pay a termination fee in the event we materially breach the Agreement.

We and the Sellers have made customary representations, warranties and covenants in the Agreement. The Sellers have made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Agreement and the closing of the Transaction and not to engage in certain kinds of transactions during that period, subject to certain exceptions.

Consummation of the Transaction is subject to various conditions, including, among others, (1) the accuracy of the representations and warranties of the parties as of the closing date, including the absence of any material adverse effect with respect to the Sellers’ business, (2) the release of certain liens in connection with the repayment of the Sellers’ indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions. The transaction will be effective April 1, 2013 and closing is expected to occur on or about May 31, 2013. The Agreement may be terminated under customary circumstances.

In connection with the execution of the Agreement, on April 3, 2013, we entered into a commitment letter to, among other things, (1) provide for an unsecured bridge credit facility in the amount of up to $620 million and (2) provide a

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commitment to amend, amend and restate, or refinance and replace the existing secured revolving credit facility (the “Amended Revolving Credit Facility”) to increase the borrowing base to $425 million and to accommodate, among other things, the issuance, incurrence and/or compliance with the terms of the bridge loans and other debt securities that may be issued or loans that may be incurred in lieu of, or in connection with the replacement of, the bridge loans, including senior unsecured notes.

The proceeds of the bridge credit facility may be used solely to fund the Transaction, to pay transaction costs and expenses in connection therewith or repay outstanding debt under the existing secured revolving credit facility.  If entered into, the Amended Revolving Credit Facility would mature on the fifth anniversary of the entrance into the facility and the aggregate amount available under the Amended Revolving Credit Facility would increase to $425 million, subject to reduction in the event that the amount of assets acquired in connection with the Transaction is less than expected. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, by $650 million.

The definitive loan documentation for the bridge loan facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to those in other similar transactions.  The definitive loan documentation for the Amended Revolving Credit Facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to the terms set forth in the existing secured revolving credit facility and which address the above mentioned accommodations and allowances.  Please read “—Liquidity and Capital Resources” for more information about the terms of the bridge credit facility and the amendment to the Amended Credit Agreement, as provided for by the commitment letter.

The availability of loans under the bridge credit facility and the effectiveness of the Amended Revolving Credit Facility are subject to the consummation of the Transaction and other customary conditions.

Operations Update

Gulf Coast Region

In our Gulf Coast region, our current acreage positions and evaluation efforts are concentrated in Louisiana in the Wilcox interval of the Upper Gulf Coast Tertiary trend.

Many of the oilfields in this trend were discovered by major oil companies in the 1940s and 1950s, but were not fully developed due to then-prevailing oil prices, the adoption of a state level severance tax in Louisiana, restrictive production allowables and other regulatory limitations. We have applied modern formation evaluation and drilling and completion techniques to the trend and our development operations in the Gulf Coast area are currently focused on drilling vertical and horizontal wells and commingling production from multi stage hydraulically fractured completions across stacked oil-producing intervals.

At March 31, 2013, our properties in the Gulf Coast region consisted of approximately 165 gross active producing wells, 96% of which we operate and in which we held an average working interest of 98%.

During the three months ended March 31, 2013, our average production from these properties was 6,740 net Boe/d, consisting of 4,517 Bbls of oil, 977 Bbls of natural gas liquids (“NGLs”), and 7,480 Mcf of natural gas. Our average production from these properties for the fourth quarter of 2012 was 8,385 net Boe/d and consisted of 5,737 Bbls of oil, 1,170 Bbls of NGLs and 8,869 Mcf of natural gas.  Production from the Gulf Coast declined by 19.7% versus the fourth quarter of 2012, primarily due to unplanned downtime, base production decline and the performance of new wells.

During the first quarter of 2013, we invested approximately $60.5 million for exploration, development and lease and seismic acquisition and drilled nine wells in the Gulf Coast area. For the remainder of 2013, we currently plan to invest between $100 million and $110 million and drill between eight to ten vertical and horizontal wells.

As of March 31, 2013, we had accumulated approximately 141,600 net acres in the trend, including options to acquire an aggregate of approximately 55,700 targeted net acres. We currently have two drilling rigs operating in this area.

Gulf Coast Areas of Operation

Our Gulf Coast areas of operation are concentrated in four core fields in Beauregard and Evangeline Parishes, Louisiana. In the first quarter of 2013, 95% of our drilling and completion capital was concentrated on our primary fields: Pine Prairie,

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South Bearhead Creek, West Gordon and North Coward’s Gully. We spud nine gross wells in the Gulf Coast region in the first quarter of 2013, including six wells in Pine Prairie targeting the Wilcox interval, one horizontal sidetrack at West Gordon, and one horizontal well in each of the South Bearhead Creek and North Cowards Gully fields.  Of these nine wells, five were producing, three were drilling and one was awaiting completion at quarter-end.  We brought a total of seven wells in the Gulf Coast region into production during the first quarter of 2013, consisting of five vertical wells in Pine Prairie, and two horizontal wells or horizontal sidetracks at West Gordon and North Cowards Gully.

For the remainder of 2013, we currently expect to drill between one and three vertical wells at Pine Prairie, between six and nine horizontal wells (including horizontal sidetracks) at our South Bearhead Creek and North Cowards Gully fields and one vertical well at South Bearhead Creek.

Expansion Areas Within Gulf Coast

We negotiated seismic options to acquire 31,700 net acres in 2011 and an additional 24,000 net acres in 2012 in the trend and committed to shoot 3D seismic over the optioned acreage. The 3D data is currently being processed with expected final delivery during the second quarter of 2013. We may acquire additional acreage within the 3D seismic shoot pending evaluation of the results. At March 31, 2013, we held approximately 123,200 gross (120,600 net) acres in these expansion areas, through lease and option, and we are currently evaluating prospects on this acreage.

In the first quarter of 2013, we did not spud or complete any wells in our Gulf Coast expansion areas. During the remainder of 2013, we currently plan to drill between one and three wells on prospects within this acreage, including acreage covered by the 3D seismic shoot discussed above.

Mid-Continent Region

Our Mid-Continent assets were acquired on October 1, 2012 and at March 31, 2013, consisted of approximately 86,000 net prospective acres in the Mississippian Lime trend, with approximately 80,400 net acres in Woods and Alfalfa Counties of Oklahoma. We also have approximately 5,600 net acres in Kansas, in which we owned an average working interest of approximately 58%. We currently intend to develop these oil and liquids rich properties using horizontal wells. We also own approximately 14,800 net acres in Lincoln County, Oklahoma, which produces primarily natural gas from the Hunton formation.

At March 31, 2013, our properties in the Mid-Continent region consisted of approximately 148 gross active producing wells, 86% of which we operate and in which we held an average working interest of 72%.

During the three months ended March 31, 2013, our average production from these properties was 9,468 net Boe/d consisting of 3,422 Bbls of oil, 2,105 Bbls of NGLs, and 23,646 Mcf of natural gas. Our average production from these properties for the fourth quarter of 2012 was 7,207 net Boe/d and consisted of 2,216 Bbls of oil, 1,820 Bbls of NGLs and 19,021 Mcf of natural gas.  While production from the Mid-Continent region increased by 31.4% versus the fourth quarter of 2012, primarily due to increased drilling activity during the period and the consequent increase in producing well count, production during the period was adversely affected by extreme winter weather that caused power failures in the area and the temporary shut-in of our production.

Mid-Continent Areas of Operation

In the Mid-Continent region, our current development drilling is targeting the Mississippian Lime interval, where we anticipate ultimate development of three to four horizontal wells per section. In the first quarter of 2013, we invested approximately $65.2 million and drilled ten operated horizontal wells; for the remainder of 2013, we plan to invest approximately $180 million to $200 million in the drilling of between 58 and 62 wells, including non-operated wells. Our plans are to continue to actively develop this area while testing expansion areas beyond our current acreage position. We currently have a total of five operated drilling rigs operating in Oklahoma and one additional drilling rig currently drilling the first of two wells intended to test the Missippian Lime on our Kansas acreage.

Expansion Areas Within Mid-Continent

Our acreage position in the Mississippian Lime that extends beyond our de-risked acreage is being tested with one rig assigned to hold our primary term acreage with production. We currently plan to continue running one (or more) rigs in these areas to not only hold acreage, but also de-risk the acreage.

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Capital Expenditures

During the three months ended March 31, 2013, we incurred capital expenditures of $132.8 million, including capitalized interest, which consisted primarily of (in thousands):

	For the Three Months Ended March 31, 2013
Drilling and completion activities	$	116,510
Acquisition of acreage and seismic data	8,236
Facilities and other	995
Capitalized interest	7,054
Total capital expenditures incurred	$	132,795

Excluding capitalized interest, of the $125.7 million spent during the first quarter in 2013, $60.5 million was spent in the Gulf Coast region and $65.2 million was spent in the Mid-Continent region.

Revolving Credit Facility

In March 2013, as part of the regularly scheduled borrowing base redetermination, our borrowing base under our revolving credit facility was increased from $250 million to $285 million.  Additionally, on April 3, 2013, as part of the Transaction, we entered into a commitment letter to amend the credit agreement, subject to the closing of the Transaction, to, among other things, increase the borrowing base to $425 million.  Please see “—Liquidity and Capital Resources — Significant Sources of Capital — Reserve-based Credit Facility” for more information.

Factors that Significantly Affect our Results

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we expect to reduce some of the variability in our cash flow from operations. See “Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Exposure” beginning on page 36 for discussion of our hedging and hedge positions.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost of such capital and operational considerations.

The volumes of oil and natural gas that we produce are driven by several factors, including:

·success in the drilling of new wells, including exploratory wells, and the recompletion of existing wells;

·the amount of capital we invest in the leasing and development of our oil and natural gas properties;

·facility or equipment availability and unexpected downtime;

·delays imposed by or resulting from compliance with regulatory requirements; and

·the rate at which production volumes on our wells naturally decline.

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Results of Operations

The following tables summarize our revenue, production and price data for the periods indicated.

Revenues

	For the Three Months Ended March 31,
	2013					2012
	(in thousands)
REVENUES:
Oil sales	$	72,218		80	%	$	45,082		82	%
Natural gas sales	8,795			9	%	3,450			6	%
Natural gas liquid sales	9,719			11	%	6,272			12	%
Total oil, natural gas, and natural gas liquids sales	90,732			100	%	54,804			100	%
Realized losses on commodity derivative contracts, net	(5,004		)	25	%	(6,499		)	26	%
Unrealized losses on commodity derivative contracts, net	(15,120		)	75	%	(18,166		)	74	%
Losses on commodity derivative contracts — net	(20,124		)	100	%	(24,665		)	100	%
Other	414					105
Total revenues	$	71,022				$	30,244

Production

	For the Three Months Ended March 31,
	2013	2012	% Change
PRODUCTION DATA:
Oil (MBbls)	714	405	76	%
Natural gas liquids (MBbls)	277	127	118	%
Natural gas (MMcf)	2,801	1,322	112	%
Oil equivalents (MBoe)	1,459	753	94	%
Oil (Boe/day)	7,939	4,455	78	%
Natural gas liquids (Boe/day)	3,082	1,400	120	%
Natural gas (Mcf/day)	31,126	14,523	114	%
Average daily production (Boe/d)	16,208	8,275	96	%

Prices

	For the Three Months Ended March 31,
	2013		2012		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	101.08	$	111.21	-9	%
Oil, with realized derivatives (per Bbl)	$	93.31	$	95.18	-1	%
Natural gas liquids, without realized derivatives (per Bbl)	$	35.04	$	49.23	-29	%
Natural gas liquids, with realized derivatives (per Bbl)	$	36.31	(a)		—
Natural gas, without realized derivatives (per Mcf)	$	3.14	$	2.61	20	%
Natural gas, with realized derivatives (per Mcf)	$	3.21	(a)		—

(a)The Company did not have hedges in place on its natural gas or NGL production until October 1, 2012.

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Three Months Ended March 31, 2013 as Compared to the Three Months Ended March 31, 2012

Oil, natural gas liquids and natural gas revenues

Our oil, natural gas and NGLs revenues increased by $35.9 million, or 66%, to $90.7 million during the first quarter of 2013, as compared to $54.8 million during the first quarter of 2012.

Our oil sales revenues increased by $27.1 million, or 60%, to $72.2 million during the quarter ended March 31, 2013, as compared to $45.1 million for the quarter ended March 31, 2012. Oil volumes sold increased 3,484 Boe/day or 78% to 7,939 Boe/day for the quarter ended March 31, 2013 from 4,455 Boe/day for the quarter ended March 31, 2012. This increase in oil volumes sold was attributable to the addition of 3,422 Boe/day of production volumes from our Mid-Continent area, which was acquired on October 1, 2012. During the quarter ended March 31, 2012, all of our production was from our Gulf Coast region. Average oil sales prices, without realized derivatives, decreased by $10.13 per barrel, or 9%, to $101.08 per barrel during the quarter ended March 31, 2013 as compared to $111.21 per barrel for the quarter ended March 31, 2012 primarily due to lower oil prices received for our Mid-Continent production, which is priced off WTI as opposed to LLS for our Gulf Coast production.

Our NGL sales revenues increased by $3.4 million, or 54%, to $9.7 million during the quarter ended March 31, 2013, as compared to $6.3 million for the quarter ended March 31, 2012. NGL volumes sold increased 1,682 Boe/day, or 120% to 3,082 Boe/day for the quarter ended March 31, 2013 from 1,400 Boe/day for the quarter ended March 31, 2012. This increase in NGL volumes sold was attributable to the addition of 2,105 Boe/day of production volumes from our Mid-Continent area, which was acquired on October 1, 2012, offset by a 423 Boe/day decrease in production from our Gulf Coast area which is directly related to the lower Gulf Coast gas production volumes discussed below. Average NGL sales prices, without realized derivatives, decreased by $14.19 per barrel, or 29%, to $35.04 per barrel during the quarter ended March 31, 2013 as compared to $49.23 per barrel for the quarter ended March 31, 2012.

Our natural gas sales revenues increased by $5.3 million, or 151%, to $8.8 million during the quarter ended March 31, 2013, as compared to $3.5 million for the quarter ended March 31, 2012. Natural gas volumes sold increased 16,603 Mcf/day or 114% to 31,126 Mcf/day for the quarter ended March 31, 2013 from 14,523 Mcf/day for the quarter ended March 31, 2012. This increase in natural gas volumes sold was attributable to the addition of 23,646 Mcf/day of production volumes from our Mid-Continent area, which was acquired on October 1, 2012, partially offset by a decrease in production of 7,043 Mcf/day from our Gulf Coast area. Average natural gas sales prices, without realized derivatives, increased by $0.53 per Mcf, or 20%, to $3.14 per barrel during the quarter ended March 31, 2013 as compared to $2.61 per Mcf for the quarter ended March 31, 2012.

Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $18.2 million for the quarter ended March 31, 2012 to an unrealized loss of $15.1 million for the quarter ended March 31, 2013. The MTM change resulted from higher average hedge volumes and unfavorable market price movements versus the average price at which our production is hedged. We entered into additional derivative contracts during 2013 and, with the closing of the Eagle Property Acquisition on October 1, 2012, we assumed the related oil, natural gas and NGL hedging instruments associated with those acquired properties. The NYMEX WTI closing price on March 30, 2012 (the last day of trading for the quarter) was $103.02 per barrel compared to a closing price of $97.23 per barrel on March 28, 2013 (the last day of trading for the quarter).

The realized loss on derivatives for the quarter ended March 31, 2013 was $5.0 million, compared to a realized loss of $6.5 million for the quarter ended March 31, 2012. As discussed above, with the closing of the Eagle Property Acquisition, we assumed the related natural gas and NGL hedging instruments. Therefore, our realized gains/losses for the quarter ended March 31, 2013 included realized gains/losses on these commodities in addition to oil. Prior to assuming these derivatives as part of this acquisition, we only hedged oil. The following table presents realized gain (loss) by type of commodity contract (in thousands):

	Three Months Ended March 31, 2013
	Realized Gain (Loss)			Average Sales Price
Oil commodity contracts	$	(5,554	)	$	93.31
Natural gas commodity contracts		198		$	3.21
Natural gas liquids commodity contracts		352		$	36.31
	$	(5,004	)

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Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and a per Boe basis. Depending on the relevance, our discussion may reference expenses on an absolute dollar basis, a per Boe basis, or both.

	Three Months Ended March 31,
	2013		2012		2013		2012
	(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	13,871	$	6,467	$	9.51	$	8.59
Severance and other taxes	5,955		5,376		$	4.08	$	7.14
Asset retirement accretion	254		134		$	0.17	$	0.18
Depreciation, depletion, and amortization	41,976		28,027		$	28.77	$	37.22
General and administrative	11,026		6,064		$	7.56	$	8.05
Total expenses	$	73,082	$	46,068	$	50.09	$	61.18

Three Months Ended March 31, 2013 as Compared to the Three Months Ended March 31, 2012

Lease operating and workover expenses

Lease operating and workover expenses increased $7.4 million, or 114%, to $13.9 million for the quarter ended March 31, 2013 compared to $6.5 million for the quarter ended March 31, 2012. Lease operating expenses increased $5.6 million, or 100%, to $11.2 million, for the first quarter of 2013 as compared to $5.6 million for the related quarter in 2012. Of this increase, approximately $4.4 million relates to the Mid-Continent area, which was acquired on October 1, 2012. During the period, due to extreme winter weather, we experienced power failures and the temporary shut-in of our production in the Mid-Continent area. As a result, we incurred additional lease operating expense during the period related to restoring power and production in our Mid-Continent area. The remaining $1.2 million increase is related to costs associated with increase in Gulf Coast producing well count, which increased by 55 wells period over period. Workover expenses increased $1.8 million, or 200%, to $2.7 million for the quarter ended March 31, 2013 compared to $0.9 million for the quarter ended March 31, 2012. Of this increase, approximately $1.6 million relates to the Mid-Continent area, which was acquired on October 1, 2012. The remaining $0.2 million of increase was driven primarily by an increase in workover activity; we completed 16 workovers during the first quarter of 2013, as compared to nine workovers in the first quarter of 2012. Lease operating and workover expenses increased to $9.51 per Boe for the quarter ended March 31, 2013, an increase of $0.92, or 11%, over the corresponding period in 2012. This increase was primarily attributable to the factors discussed above.

Severance and other taxes

	Three Months Ended March 31,
	2013			2012
Total oil, natural gas, and natural gas liquids sales	$	90,732		$	54,804
Severance taxes	4,852			4,483
Ad valorem	1,103			893
Severance and other taxes	5,955			5,376
Severance taxes as a percentage of sales	5.3		%	8.2		%
Severance and other taxes as a percentage of sales	6.6		%	9.8		%

Severance and other taxes increased $0.6 million, or 11%, to $6.0 million for the three months ended March 31, 2013 compared to $5.4 million for the three months ended March 31, 2012. Severance taxes increased $0.4 million, or 9%, to $4.9 million for the three months ended March 31, 2013, as compared to $4.5 million for the three months ended March 31, 2012. This increase was attributable to higher oil, natural gas and NGL sales, partially offset by the lower effective severance tax rate in Oklahoma applicable to production from the Mid-Continent region. Ad valorem taxes increased $0.2 million, or 22%, to $1.1 million for the first quarter of 2013 as compared to $0.9 million for the first quarter of 2012, corresponding to a related increase in producing wells.

Depreciation, depletion and amortization (DD&A)

DD&A expense increased $14.1 million, or 50%, to $42.0 million for the first quarter of 2013 compared to $28.0 million for the first quarter of 2012. The DD&A rate for first quarter of 2013 was $28.77 per Boe compared to $37.22 per Boe for the

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first quarter of 2012. The decrease in DD&A rate was due to the addition of reserves in the Mid-Continent region on October 1, 2012, as well as year over year proved reserve growth in the Gulf Coast region.

General and administrative (G&A)

Our G&A expenses increased by $4.9 million, or 80%, to $11.0 million for the three months ended March 31, 2013, compared to $6.1 million for the three months ended March 31, 2012. The increase is attributable to $0.8 million in other taxes, $0.7 million in professional fees (primarily legal), $0.8 million in payments to Eagle under the related Transition Services Agreement, and approximately $2.6 million in additional employee related expenses (including salary, stock compensation expense and bonus) related to an increase in headcount from 63 full time employees at March 31, 2012 to 124 full time employees at March 31, 2013.

Other Income (Expenses)

	For the Three Months Ended March 31,
	2013			2012
	(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	5		$	7
Interest expense	(17,921		)	(2,363		)
Capitalized Interest	7,054			673
Interest expense — net of amounts capitalized	$	(10,867	)	$	(1,690	)
Total other income (expense)	$	(10,862	)	$	(1,683	)

Three Months Ended March 31, 2013 as Compared to the Three Months Ended March 31, 2012

Interest expense

Interest expense for the three months ended March 31, 2013 and 2012 was $17.9 million and $2.4 million, respectively. The increase in interest expense was primarily due to the issuance of $600 million of 10.75% senior unsecured notes in October 2012. Our average outstanding balance under the revolver was $137.8 million during the 2013 period, compared to $234.8 million for the 2012 period, and related to $0.8 million of the total interest expense of $17.9 million for 2013. Of the remainder of the interest, $16.1 million was interest incurred under the senior notes and $1.0 million represented amortization of deferred financing costs. Of total interest expense, $7.1 million and $0.7 million was capitalized, resulting in $10.9 million and $1.7 million in interest expense, net of capitalized interest, for the three months ended March 31, 2013 and 2012, respectively.

Provision for Income Taxes

Three Months Ended March 31, 2013 as Compared to the Three Months Ended March 31, 2012

Our income tax benefit was $5.0 million for the three months ended March 31, 2013. We were not a tax paying entity during the 2012 corresponding period and therefore, no income tax expense was recorded. The resulting income tax benefit for the three months ended March 31, 2013 represents an effective tax benefit rate (including state income taxes) of approximately 39%.

Liquidity and Capital Resources

At March 31, 2013, our liquidity was $139 million, consisting of $88 million of available borrowing capacity under our revolving credit facility (which at that date, consisted of a borrowing base of $285 million) and $51 million of cash and cash equivalents.

Recent Developments Impacting our Liquidity

Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital. In the event that the Transaction closes during the second quarter of 2013, we anticipate that the financing activities undertaken in connection with that acquisition, our available cash, execution of our planned drilling program,

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anticipated future cash flows from operations and borrowings under our revolving credit facility will be sufficient to meet our operating needs through at least the second quarter of 2014. In the event we are unable to access additional funding through debt or equity markets or secure other external sources of funding, we could be required to reduce our future capital program. If we reduce our future planned exploration and development expenditures, we believe that those steps, together with our available cash, anticipated future cash flows from operations and borrowings under our revolving credit facility will be sufficient to meet our reduced expenditures and operating needs beyond the second quarter of 2014.

Commitment Letter for Bridge Credit Facility and Amendment to Revolver

As part of the Transaction, we will be required to provide $620 million of cash consideration, subject to adjustment as provided in the Agreement, and pay transaction costs and expenses, including advisors’ fees.

In connection with the execution of the Agreement, on April 3, 2013, we entered into a commitment letter with Morgan Stanley Senior Funding, Inc., SunTrust Bank and SunTrust Robinson Humphrey, Inc. to, among other things, (1) provide for an unsecured bridge credit facility in the amount of up to $620 million and (2) provide a commitment to amend, amend and restate, or refinance and replace the existing secured revolving credit facility (the “Amended Revolving Credit Facility”) to increase the borrowing base to $425 million and to accommodate, among other things, the issuance, incurrence and/or compliance with the terms of the bridge loans and other debt securities that may be issued or loans that may be incurred in lieu of, or in connection with the replacement of, the bridge loans, including senior unsecured notes. The availability of loans under the bridge credit facility and the effectiveness of the Amended Revolving Credit Facility are subject to the consummation of the Transaction and other customary conditions.

The proceeds of the bridge credit facility may be used solely to fund the Transaction, to pay transaction costs and expenses in connection therewith or repay outstanding debt under the existing secured revolving credit facility. If entered into, the bridge credit facility will initially bear interest at LIBOR, subject to a 1.50% floor, plus either 7.50% or 8.00% (based on the indicative rating(s) received in respect of the bridge facility or senior unsecured notes) and thereafter such margin is subject to increases. The bridge credit facility matures on the first anniversary of the closing date of the Transaction and contains customary terms regarding the conversion of the bridge loans into other debt instruments subject to certain caps on yield, the highest of which is set at 11.50%. The obligations under the bridge credit facility would be guaranteed by the same entities that guarantee our existing Credit Facility.

If entered into, the Amended Revolving Credit Facility would mature on the fifth anniversary of the entrance into the facility and the aggregate amount available under the credit facility would increase to $425 million, subject to reduction in the event that the amount of assets acquired in connection with the Transaction is less than expected. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, by $650 million, thereby permitting the incurrence of the bridge loans or the issuance of other debt without causing a $0.25 reduction in the borrowing base for every $1 of such debt incurred or issued. The definitive loan documentation for the bridge loan facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to those in other similar transactions. The definitive loan documentation for the Amended Revolving Credit Facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to the terms set forth in our existing Credit Facility and which address the above mentioned accommodations and allowances.

Significant Sources of Capital

Reserve-based Credit Facility

As of March 31, 2013, our credit facility consisted of a $500 million senior revolving credit facility (the “Credit Facility”) with a borrowing base of $285 million, as recently redetermined in March 2013 when the borrowing base was increased from $250 million.

Borrowings under the Credit Facility are secured by substantially all of our oil and natural gas properties and currently bear interest at LIBOR plus an applicable margin between 1.75% and 2.75% per annum. At March 31, 2013 and March 31, 2012, the weighted average interest rate was 2.4% and 3.1%, respectively.

In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

The borrowing base under the Credit Facility is subject to semiannual redeterminations in March and September and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by us or the administrative agent, acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations. The next scheduled borrowing base redetermination date is September 2013.

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Under the terms of the Credit Facility, we are required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. We are permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

The Credit Facility contains financial covenants, which, among other things, set a maximum ratio of debt to earnings before interest, income tax, depletion, depreciation, and amortization (EBITDA) of not more than 4.0 to 1, a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, but not limited to, restrictions on our ability to make any dividends, distributions or redemptions.

As of March 31, 2013, we were in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. Our current ratio at March 31, 2013 was 1.4 to 1.0. At March 31, 2013, our ratio of debt to EBITDA was 3.48.

Senior Notes Offering

On October 1, 2012, we issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the “Senior Notes”) in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. The proceeds from the offering of $582 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the cash portion of, and expenses related to, the Eagle Property Acquisition, to pay the expenses related to the amendments to the revolving credit facility, to repay $182.9 million in outstanding borrowings under the our Credit Facility, and for general corporate purposes.

The Notes were co-issued on a joint and several basis by Midstates Petroleum Company, Inc. and its wholly owned subsidiary, Midstates Petroleum Company LLC. Midstates Petroleum Company, Inc. does not have any operations or independent assets other than its 100% ownership interest in Midstates Petroleum Company LLC and there are no other subsidiaries of the Company. The Notes indenture does not create any restricted assets within Midstates Petroleum Company LLC, nor does it impose any significant restrictions on the ability of Midstates Petroleum Company LLC to pay dividends or make loans to Midstates Petroleum Company, Inc. or limit the ability of Midstates Petroleum Company, Inc. to advance loans to Midstates Petroleum Company LLC.

At any time prior to October 1, 2015, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, we may redeem all or a part of the Senior Notes at a redemption price equal to 100% of the principal amount of Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, up to, the redemption date.

On or after October 1, 2016, we may redeem all or a part of the Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, on the Senior Notes redeemed, up to, the redemption date. The Indenture contains covenants that, among other things, restrict our ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with our affiliates; (vii) consolidate, merge or sell substantially all of our assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business we conduct and (x) enter into agreements restricting the ability of our subsidiaries to pay dividends.

Upon the occurrence of certain change of control events, as defined in the Indenture, each holder of the Senior Notes will have the right to require that we repurchase all or a portion of such holder’s Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase. In connection with the private placement of the Senior Notes, on October 1, 2012, we entered into a Registration Rights Agreement (the “Notes Registration Rights Agreement”) obligating us to use reasonable best efforts to file an exchange registration statement with the Securities and Exchange Commission (the “Commission”) so that holders of the Senior Notes can offer to exchange the Senior Notes offering for registered notes having substantially the same terms as the Senior Notes and evidencing the same indebtedness as the Senior Notes. Under certain

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circumstances, in lieu of a registered exchange offer, we must use reasonable best efforts to file a shelf registration statement for the resale of the Senior Notes. If the Issuers fail to satisfy these obligations on a timely basis, the annual interest borne by the Senior Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

Series A Preferred Stock

On October 1, 2012 we issued 325,000 shares of our Series A Preferred Stock as part of the purchase price paid to complete the Eagle Property Acquisition. The shares of Series A Preferred Stock have an initial liquidation value of $1,000 per share and are convertible into shares of our common stock on or after October 1, 2013. At such time, the Series A Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number of shares of our common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. If not previously converted, the Series A Preferred Stock will be subject to mandatory conversion into shares of our common stock on September 30, 2015 at a conversion price based upon the volume weighted average price of our common stock during the 15 trading days immediately prior to the mandatory conversion date, but in no instance will the price be greater than $13.50 per share or less than $11.00 per share. Dividends on the Series A Preferred Stock will accrue at a rate of 8.0% per annum, payable semiannually, at our sole option, in cash or through an increase in the liquidation preference. The issuance of the Series A Preferred Stock to Eagle pursuant to the Eagle Purchase Agreement was approved by our stockholders holding a majority of the outstanding shares of our common stock.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods presented (dollars in thousands). For information regarding the individual components of our cash flow amounts, please refer to the Unaudited Condensed Consolidated Statements of Cash Flows included under Item 1 of this quarterly report.

	For the Three Months Ended March 31,
	2013			2012
Net cash provided by operating activities	$	62,203		$	34,316
Net cash used in investing activities	(132,538		)	(72,466		)
Net cash provided by financing activities	102,082			40,000
Net change in cash	$	31,747		$	1,850

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3. — Quantitative and Qualitative Disclosures About Market Risk” beginning on page 36.

The following information highlights the significant period-to-period variances in our cash flow amounts:

Cash flows provided by operating activities

Net cash provided by operating activities was $62.2 million and $34.3 million for the three months ended March 31, 2013 and 2012, respectively. The increase in net cash provided by operating activities was primarily the result of an increase in production and favorable working capital changes, partially offset by decreases in realized oil, natural gas and NGL prices.

Cash flows used in investing activities

Net cash used in investing activities was $132.5 million and $72.5 million during the three months ended March 31, 2013 and 2012, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in our investing activities during the 2013 period is attributable to continued expansion of our drilling program and acreage position, as well as the addition of our Mid-Continent properties effective October 1, 2012.

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Cash flows provided by financing activities

Net cash provided by financing activities was $102.1 million and $40.0 million for the three months ended March 31, 2013 and 2012, respectively. During the first quarter of 2013, cash was sourced through the revolving credit facility, with draws of $102.5 million during the period. During the first quarter of 2012, $40.0 million was provided through issuance of mandatorily redeemable convertible preferred units, which were subsequently repaid in April of 2012 with the proceeds from our initial public offering.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in Midstates Petroleum Company, Inc.’s Annual Report on Form 10-K. There have been no material changes to those policies.

When used in the preparation of our unaudited condensed consolidated financial statements, estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our condensed consolidated financial position, results of operations and cash flows.

Other Items

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2013, and determined that none would have a material impact on our condensed consolidated financial statements.

Item 3. — Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “Item 1.—Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements — Note 4. Risk Management and Derivative Instruments.”

Commodity Price Exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged in the past and expect to hedge a significant portion of our future production.

We utilize derivative financial instruments to manage risks related to changes in oil prices. As of March 31, 2013, we utilized fixed price swaps, collars, deferred-premium puts and basis differential swaps to reduce the volatility of oil prices on a portion of our future expected oil production.

For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

The following is a summary of our commodity derivative contracts as of March 31, 2013:

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	Hedged Volume	Weighted-Average Fixed Price
Oil (Bbls):
WTI Swaps — 2013	1,827,674				$	95.16
WTI Swaps — 2014	2,425,950				$	88.98
WTI Swaps — 2015	1,460,000				$	86.69
WTI Collars — 2013	152,253	$	85.27	-	$	100.70
WTI Collars — 2014	164,400	$	88.49	-	$	97.94
WTI to LLS Basis Differential Swaps — 2013 (1)	1,182,764				$	5.83
WTI to LLS Basis Differential Swaps — 2014 (1)	501,000				$	5.35
Natural Gas (Mmbtu):
Collars — 2013	1,674,747	$	3.68	-	$	4.91
Collars — 2014	1,685,004	$	3.99	-	$	5.09
NGL (Bbls):
NGL Swaps — 2013	193,500				$	63.42
NGL Swaps — 2014	151,500				$	62.16

(1)We enter into swap arrangements intended to capture the positive differential between the Louisiana Light Sweet (“LLS”) pricing and West Texas Intermediate (“NYMEX WTI”) pricing.

	Three Months Ended March 31, 2013
	(in thousands)
Derivative fair value at period end - liability (included in balance sheet)	$	19,233
Realized net loss (included in the statement of operations)	$	(5,004	)
Unrealized net gain (included in the statement of operations)	$	(15,120	)

At March 31, 2013 and December 31, 2012, all of our commodity derivative contracts were with six and five bank counterparties, respectively. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

Interest Rate Risk. At March 31, 2013, we had indebtedness outstanding under our credit facility of $196.5 million, which bore interest at floating rates, and we had $600 million outstanding in Senior Notes, which bore interest at 10.75%. The average annual interest rate incurred on this combined indebtedness for the three months ended March 31, 2013 and 2012 was 9.3% and 3.1%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended March 31, 2013 and 2012 would have resulted in an estimated $1.8 million and $0.6 million, respectively, increase in interest expense, of which a portion may be capitalized.

We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. At March 31, 2013, we do not have any interest rate derivatives in place.

In the future, we may utilize interest rate derivatives to mitigate our exposure to change in interest rates. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Item 4. — Controls and Procedures

Evaluation of Disclosure Controls and Procedures

During the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our President and Chief

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Executive Officer and our Executive Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures at March 31, 2013 are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting except that during the quarter ended March 31, 2013, we began implementing a new accounting, production and land IT system that, once fully implemented, is expected to significantly improve our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 12 to our unaudited condensed consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

The following risks are provided to supplement the risk factors that appear in the Company’s Annual Report on Form 10-K for the year ending December 31, 2012.

We are subject to risks in connection with acquisitions, including the Transaction, and the integration of significant acquisitions may be difficult.

We have entered into a purchase agreement for the Transaction. Although it is expected to close on or about May 31, 2013, it may not close as expected and we may not incur the expected benefits therefrom.  In addition, we will continue to evaluate other acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of substantially all the assets purchased in the Transaction or other producing properties requires an assessment of several factors, including:

·recoverable reserves;

·future oil and natural gas prices and their appropriate differentials;

·development and operating costs;

·potential for future drilling and production;

·validity of the Sellers’ title to the properties, which may be less than expected at the time of signing the purchase agreement; and potential environmental issues, litigation and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Sellers may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Indemnification from the Sellers will generally be limited to 20% of the purchase price, effective only during the 12-month period after the closing and subject to certain dollar limitations and minimums.

Significant acquisitions and other strategic transactions may involve other risks, including:

·diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

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·the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

·difficulty associated with coordinating geographically separate organizations;

·an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and

·the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations, including the operations acquired in the Transaction, could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate the operations acquired in the Transaction or another acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key personnel, an increase in operating or other costs or other difficulties. We may experience additional challenges integrating the assets of privately operated companies. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may be adversely affected.

As a consequence of the Transaction, we will incur substantial additional indebtedness and may materially reduce our cash balance.

Pursuant to the terms of the Agreement, the total cash consideration to be paid by the Company for the Transaction is $620 million, subject to customary adjustments to reflect the economic effective date of April 1, 2013 and claims for title and environmental defects. We will also incur material costs and expenses in connection with the consummation and integration of the Transaction. Specifically, in connection with the Transaction, we expect to incur an additional indebtedness.  As of March 31, 2013, as adjusted to give effect to the Transaction and after giving effect to our increased borrowing base under our revolving credit facility and utilization of the bridge facility, we would have in excess of $1.4 billion of debt outstanding and a borrowing base of $425 million under our revolving credit facility, approximately $229 million of which would be available for future borrowings. We have entered into a 364-day bridge term loan facility to provide debt financing for the transaction, subject to customary conditions. We expect to consider opportunities to replace that facility either before or after the closing of the acquisition, which could include replacing that debt financing through offerings in the debt and/or equity capital markets. However, we may not be able to replace or refinance the bridge facility in a timely manner, or at all. In such event, our potential lower cash balance and increased indebtedness resulting from the proposed acquisition financing could adversely affect our business. In particular, it could increase our vulnerability to sustained, adverse macroeconomic weakness, limit our ability to obtain further financing and limit our ability to pursue certain operational and strategic opportunities.  In addition, the covenants contained in the agreements governing our outstanding indebtedness will limit, among other things, our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments and any indenture for high yield debt securities may impose more stringent covenants than our existing credit agreement. For more information about the risks the Company may face as a result of our level of indebtedness, please read “Risk Factors - Our level of indebtedness may increase and reduce our financial flexibility.” in our Annual Report on Form 10-K for the year ending December 31, 2012.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

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Item 5. Other Information

None.

Item 6. Exhibits.

Exhibits included in this Report are listed in the Exhibit Index and incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	MIDSTATES PETROLEUM COMPANY, INC.
Dated: May 8, 2013	/s/ John A. Crum
	John A. Crum
	Chief Executive Officer and President
	(Principal Executive Officer)
Dated: May 8, 2013	/s/ Thomas L. Mitchell
	Thomas L. Mitchell
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
Dated: May 8, 2013	/s/ Nelson M. Haight
	Nelson M. Haight
	Vice President and Controller
	(Principal Accounting Officer)

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EXHIBIT INDEX

Exhibit Number	Exhibit Description
2.1	Master Reorganization Agreement, dated April 24, 2012, by and among the Company and certain of its affiliates, certain members of the Company’s management and certain affiliates of First Reserve Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference).
2.2	Purchase and Sale Agreement, dated as of April 3, 2013, by and among Midstates Petroleum Company LLC, Panther Energy Company, LLC, Red Willow Mid-Continent, LLC and Linn Energy Holdings, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 4, 2013, and incorporated herein by reference).
3.1	Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference).
3.2	Amended and Restated Bylaws of Midstates Petroleum Company, Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference).
3.3	Certificate of Designations of Series A Mandatorily Convertible Preferred Stock of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on February 29, 2012, and incorporated herein by reference).
4.2	Indenture, dated October 1, 2012, by and among the Company, Midstates Petroleum Company LLC and Wells Fargo Bank, National Association, as trustee, governing the 10.75% senior notes due 2020 (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
4.3	Registration Rights Agreement, dated October 1, 2012, by and among the Company, Midstates Petroleum Company LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein, relating to the 10.75% senior notes due 2020 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
4.4	Registration Rights Agreement, dated October 1, 2012, by and among the Company, Eagle Energy Production, LLC, FR Midstates Interholding, LP and certain other of the Company’s stockholders (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
10.1	Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 19, 2013, among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, SunTrust Bank, as administrative agent, and the other lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 22, 2013, and incorporated herein by reference).
10.2	Midstates Petroleum Company, Inc. 2012 Long-Term Incentive Plan Form of Restricted Stock Agreement (Time Vesting) (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 27, 2013, and incorporated herein by reference).
31.1*	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.DEF	XBRL Definition Linkbase Document
101.LAB	XBRL Labels Linkbase Document
101.PRE	XBRL Presentation Linkbase Document
*	Filed herewith
**	Furnished herewith

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